This invention relates to the recovery of oil from subterranean reservoirs and more particularly concerns an improved process for recovering oil from porous reservoirs having heterogeneous permeability, utilizing the injection of a silicate solution.
Significant quantities of crude oil exist in underground formations. These substantial amounts remain even after completion of primary recovery operations. Because of this, techniques have been developed for stimulating production from such reservoirs. Such methods include water flooding, gas flooding, steam injection, foam emplacement, and polymer gel emplacement, but none to date have been very successful. Poor sweep efficiency has been a concern in many gas floods and mature waterfloods. Because of reservoir heterogeneity, the injected water or gas tends to flow through the more permeable sands, leaving a significant portion of oil in the less permeable sands unrecovered. The objective of this invention is to recover that ordinarily unrecoverable oil by improving the sweep efficiency of water, gas, or steam in the reservoir.
Generally, water flooding is ineffective for displacing the oil, because of the high oil-water interfacial tension and the rich viscosity of the oil. Steam injection lowers the viscosity of the oil, but requires the availability of inexpensive fuel and a large supply of clean water.
The areal sweep efficiency of carbon-dioxide recovery can be increased by generating a foam in situ to block the highly permeable features of the underground formation. U.S. Pat. No. 3,342,256, issued to Bernard et al., discloses alternative methods for generating foam in situ to prevent channeling of carbon dioxide into high permeability channels away from the zone to be treated. A subsequently injected drive medium, such as water, forces the carbon dioxide-surfactant mixture through the formation to a production well where production continues until the produced fluids exhibit an undesirably high water/oil ratio. Production is then terminated, and the formation is depressurized to allow dissolved gases to come out of solution and form the foam. As the foam expands, it drives additional oil towards the producing well.
Relying upon gases released in low pressure zones to generate the foam, however, presents certain disadvantages. When the foaming agent is dissolved directly into carbon dioxide or into carbonated water, a large portion of the gaseous carbon dioxide released in the low pressure zone does not go to generating foam, but is preferentially absorbed into the crude. And if the released carbon dioxide migrates into a high pressure region, solubility of carbon dioxide is increased and may approach miscibility at pressures in excess of about 700 psig. These difficulties are not encountered if the foaming agent is dissolved in a hydrocarbon vehicle, but the cost of liquid hydrocarbons is generally prohibitive. Moreover, a hydrocarbon-soluble surface-active agent generally emulsifies the oil and restricts its movement through the reservoir. The upshot is that increasing the areal sweep efficiency of the recovery method by generating foam in situ is much more difficult and expensive in the reservoir than laboratory results might otherwise indicate.
Polymer gels are known in the industry, as described in U.S. Pat. No. 5,079,278 issued to Mitchell, and U.S. Pat. Nos. 4,928,766, 4,981,520, and 5,028,344 issued to Hoskin. U.S. Patent Nos. 4,009,755, 4,069,869, and 4,413,680 issued to Sandiford, teach methods of injecting a polymer and an alkaline metal silicate to form a plug to reduce permeability of a selected zone. However, several factors limit the effectiveness and feasibility of polymer gel treatments. One is that the polymer solution generally has a higher viscosity than the reservoir fluid. As a result, the polymer solution tends to enter the lower permeability sands proportionately more than the higher permeability sands. When polymer gels are subsequently formed in situ, they may reduce the permeability of the tighter sands to a greater extent, resulting in worse injection or production profiles than before the gel treatment. Not surprisingly, many polymer gel treatments attempt to confine polymer injection into selective zones of high-permeability sands. This requirement excludes many potential applications because of the mechanical condition of the wells. Also, knowledge of the location and size of the high-permeability sands is essential for successful treatments.
The second limitation is that polymer gels are normally set in a few hours. This necessitates the use of experienced service companies with dedicated equipment to conduct gel treatments; it also limits the treatment volume to a few hundreds of barrels in most cases. The depth of gel invasion in the reservoir, while dependent on such variables as sand thickness, permeability distribution, polymer and reservoir fluid viscosities, and fluid saturations in the reservoir, is typically less than 40 ft. The effectiveness of such near-wellbore treatments is limited if the reservoir has some degree of cross-flow.
U.S. Pat. No. 2,081,541 teaches a method of sand control by injecting a mixture of silica acid, ZnCl.sub.2 and NH.sub.3, followed by injection of an inert gas to dispel NH.sub.3 and to solidify the mixture.
U.S. Pat. No. 3,741,307 teaches a method of controlling the gelation time of a silica gel comprising sodium silicate and a weak acid, by adjusting the pH.
The prior work is limited in the attempts at silica gel emplacement. No suitable method has been disclosed which injects a silicate solution and either a gas or a gas and an organic acid to form a controlled amount of a silicate gel in high-permeability thief zones, to reduce the permeability thereof.